Field
Embodiments of the present invention relate generally to the field of separation of carbon dioxide from a gas stream.
Description of Related Art
Carbon dioxide is present in produced natural gas streams and gas streams from oil and gas reserves, especially in gas streams from enhanced oil recovery processes. Carbon dioxide is produced as part of several industrial processes, including but not limited to, hydrocarbon processing plants, other oil, gas, and coal processing plants, and other chemical production plants. Carbon dioxide management can be an essential strategy for these processing and production facilities to achieve environmental compliance and also to optimize production from the facility. Traditional carbon dioxide treatment and separation processes include one of several technologies, including absorption, adsorption, cryogenic separation, membrane separation, bio-fixation and other separation systems. While separation processes have their merits, many have inherent disadvantages.
A common technology used for acid gas removal in natural gas processing is aqueous amine systems. Amine systems can be large and complicated processes that are highly energy inefficient due to high energy requirements for regeneration. For example, temperatures in the range of about 120° C. to about 140° C. are required. Furthermore, aqueous amines are prone to foaming and are corrosive in nature; often components and piping require stainless steel for construction. Aqueous amines also form non-regenerative, degradative compounds in the system that need to be periodically removed. Moreover, with adsorber columns, regenerative columns, flash tanks, reboilers, and water treatment systems, amine systems have a large equipment footprint and are typically not modular in design, making these acid gas removal systems costly and unsuitable for many gas capture applications, such as offshore use.
A simpler separation process, such as membrane separation, does not require an immersion into an aqueous phase, and can process large volumes in a relatively small footprint, especially when compared to more conventional systems employing amine technology. The modularity and lack of mechanical complexity also allow for easy scale-up and flexibility. FIG. 1 illustrates membrane-based separation units that are usually employed for carbon dioxide separation from an exemplary inlet gas stream. Exemplary inlet gas stream 101 is introduced to a first membrane-based separation unit 102. The retentate gas stream 109 is supplied as sales gas. The permeate byproduct gas stream 103 from this first membrane-based separation unit 102 is optionally supplied to a compressor 104 and further introduced by stream 105 to a second membrane-based separation unit 106 for increased product recovery. The permeate 107 from the second membrane-based separation unit 106 is usually a low British Thermal Unit (BTU) flare gas and still has a considerable amount of carbon dioxide. Typically, about 10-20% volume of the retentate gas 108 from the second membrane-based unit 106 is recycled back to the first membrane-based separation unit 102 to enhance product recovery.
A second membrane-based separation unit, or stage, is required because there is a trade-off between selectivity and permeability with membranes. Therefore in many instances, simple single-stage membrane systems may not be able to achieve the product purity required and/or product recovery is also decreased due to product slippage through the membrane. Therefore, energy intensive compression, a recycle stream and a second stage of membrane separation is required to reduce product loss. Additionally, to account for the extra recycle volume, either or both of the gas treatment capacity and surface area of the initial membrane has to be increased.
Another gas separation technique used in specialty gas production, such as oxygen, nitrogen, and hydrogen production, but traditionally not applied to natural gas separation, is pressure swing adsorption (PSA). PSA can achieve excellent purity by adsorbing the target component to be purified, but is usually not appropriate for natural gas separation processes because of the large volumes involved. PSA is an intrinsically clean technology when compared to amines, which are toxic, can be corrosive, and typically require significant heat input to be regenerated, but ultimately form a waste product. In addition, PSA produces a methane product that, unlike amine absorption, does not require a post-processing step for dehydration, and it does not depend on heat for regeneration. However, PSA units may not be the best option in streams with very low partial pressures of contaminant gas species. Moreover, because of its focused development for specialty gas production, there is relatively little focus on large scale systems and PSA development for natural gas purification.
Traditionally, a desired, higher-value end product, such as methane, is “captured” while contaminants, such as CO2 and H2S, are passed through the system. Existing product recovery systems do not contemplate using PSA for high volume natural gas processing, because there has not been an economical or functional way to use such a system. PSAs have traditionally been used for high-purity product processes where high recovery may be appreciated, but is not necessary; for example, hydrogen purification for refining using PSA (99.99+% purity) or nitrogen purification from air for the electronics industry or hypoxic fire prevention systems by PSA (99.9% purity). In these examples, product purity is more critical than product recovery.
In prior systems, PSA units have been used to polish valuable product streams, such as, for example, a retentate stream containing products of value, such as natural gas. However, products of value are wasted because the waste streams of primary separations, such as the permeate byproduct stream of a membrane separation, still contain valuable product, and so too does the waste stream, or “tail gas,” of the PSA used to polish the valuable product stream. Prior systems have not used PSA to enhance recovery of valuable product lost through the waste stream of a primary separation, such as, for example, a membrane. There is a need for systems and methods that can not only obtain substantially pure product streams such as natural gas, but also recover potential product lost during separation and delivery, including substantially pure byproduct streams such as CO2 and H2S.